Three Rivers Royalty II, LLC and Cypress Mineral Partners, LLC

Combined Financial Report

with Supplemental Information (Unaudited)

December 31, 2025

Three Rivers Royalty II, LLC and Cypress Mineral Partners, LLC

Contents

Independent Auditor's Report

To the Member

Three Rivers Royalty II, LLC and

Cypress Mineral Partners, LLC

Opinion

We have audited the combined financial statements of Three Rivers Royalty II, LLC and Cypress Mineral Partners, LLC (collectively, the "Company"), which comprise the combined balance sheet as of December 31, 2025 and 2024 and the related combined statements of operations, changes in member's equity, and cash flows for the years then ended, and the related notes to the combined financial statements.

In our opinion, the accompanying combined financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024 and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

Basis for Opinion

We conducted our audits in accordance with auditing standards generally accepted in the United States of America (GAAS). Our responsibilities under those standards are further described in the Auditor's Responsibilities for the Audits of the Combined Financial Statements section of our report. We are required to be independent of the Company and to meet our ethical responsibilities in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Emphasis of Matter

We draw attention to Note 2, which describes the basis of presentation of the accompanying combined carve-out financial statements. These combined carve-out financial statements have been derived from the historical accounting records of San Jacinto Minerals II, LLC and its consolidated subsidiaries and reflect the revenue and costs and assets and liabilities directly associated with the Company, as well as allocations of other amounts. Our opinion is not modified with respect to this matter.

Responsibilities of Management for the Combined Financial Statements

Management is responsible for the preparation and fair presentation of the combined financial statements in accordance with accounting principles generally accepted in the United States of America and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of combined financial statements that are free from material misstatement, whether due to fraud or error.

In preparing the combined financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company's ability to continue as a going concern within one year after the date that the combined financial statements are issued or available to be issued.

To the Member

Three Rivers Royalty II, LLC and

Cypress Mineral Partners, LLC

Auditor’s Responsibilities for the Audits of the Combined Financial Statements

Our objectives are to obtain reasonable assurance about whether the combined financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor's report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and, therefore, is not a guarantee that audits conducted in accordance with GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the combined financial statements.

In performing audits in accordance with GAAS, we:

We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audits, significant audit findings, and certain internal control-related matters that we identified during the audits.

/s/ Plante & Moran, PLLC

Denver, Colorado

September 11, 2026

Three Rivers Royalty II, LLC and Cypress Mineral Partners, LLC

Combined Balance Sheet

December 31, 2025 and 2024

See notes to combined financial statements.

Three Rivers Royalty II, LLC and Cypress Mineral Partners, LLC

Combined Statement of Operations

Years Ended December 31, 2025 and 2024

See notes to combined financial statements.

Three Rivers Royalty II, LLC and Cypress Mineral Partners, LLC

Combined Statement of Changes in Member's Equity

Years Ended December 31, 2025 and 2024

See notes to combined financial statements.

Three Rivers Royalty II, LLC and Cypress Mineral Partners, LLC

Combined Statement of Cash Flows

Years Ended December 31, 2025 and 2024

See notes to combined financial statements.

Note 1 - Nature of Business

Three Rivers Royalty II, LLC (TRR II), a Colorado limited liability company, was formed on April 4, 2017 for the purpose of managing and acquiring mineral and royalty assets for lease and royalty revenue. TRR II owns oil and natural gas mineral and royalty interests in the Appalachian basin in Pennsylvania and West Virginia.

Cypress Mineral Partners, LLC (CMP), a Louisiana limited liability company, was formed on March 23, 2017 for the purpose of managing and acquiring mineral and royalty assets for lease and royalty revenue. CMP owns oil and natural gas mineral and royalty interests in the Haynesville basin in Louisiana.

TRR II and CMP are collectively referred to herein as the "Company."

TRR II and CMP are wholly owned subsidiaries of San Jacinto Minerals II, LLC (SJM II).

SJM II and its affiliated entities, San Jacinto Minerals, LLC (SJM I); San Jacinto Minerals III, LLC (SJM III); and San Jacinto Minerals IV, LLC (SJM IV) (collectively, the "SJM Entities"), share common ownership and common management. Under a management services agreement between SJM II and the other SJM Entities (the "MSA"), SJM II is the named employer of those individuals providing services to the SJM Entities. Labor and other shared expenses are allocated amongst the SJM Entities based on the hours spent of such personnel (see Note 9). Direct costs of each of the individual SJM Entities are recorded based on the actual amounts incurred and recorded to the specific entity for which it relates. In addition to allocating the costs amongst the SJM entities, costs allocable to SJM II are allocated amongst TRR II, CMP, and the other wholly owned subsidiaries of SJM II: Bluebird Energy Partners, LLC (BEP); Old River Royalty, LLC (ORR); and 1836 Mineral Company, LLC (1836), based on their respective proportion of revenue and capital expenditures. In addition, TRR II, CMP, BEP, and 1836 are all guarantors (the "Guarantors") under the SJM II Credit Agreement (see Note 5).

Note 2 - Significant Accounting Policies

Basis of Presentation

The combined carve-out financial statements of the Company are presented in accordance with accounting principles generally accepted in the United States of America (GAAP) are presented on a combined basis which includes the accounts of the commonly controlled and managed entities of TRR II and CMP. All intercompany transactions and balances have been eliminated in combination.

TRR II and CMP have historically operated as part of SJM II and not as stand-alone companies. The accompanying combined carve-out financial statements represent the historical operations of TRR II and CMP and have been derived from SJM II’s historical accounting records. All revenue and costs and assets and liabilities directly associated with TRR II and CMP are included in the combined carve-out financial statements. The combined carve-out financial statements also include allocations of certain general and administrative expenses, including unit-based compensation expense, from SJM II. However, amounts recognized by TRR II and CMP are not necessarily representative of the amounts that would have been reflected in the financial statements had TRR II and/or CMP been operated independently of SJM II. Related party allocations are discussed further in Notes 1, 2, 5, 8, and 9.

Use of Estimates

The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect amounts reported in the financial statements. Actual results could differ from those estimates.

Depreciation, depletion, and amortization (DD&A) and impairment of proved oil and gas properties are determined using estimates of proved oil and gas reserves. There are numerous uncertainties in estimating the quantity of reserves and in projecting the future rates of production and timing of development expenditures. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. The recoverability of unproved oil and gas properties, the estimated fair value of commodity derivatives allocable to the Company, and the allocation of certain expenses not specifically identifiable to the Company's revenue-producing activities are also subject to estimation. As a royalty owner, the Company is not responsible for any reclamation costs.

Note 2 - Significant Accounting Policies (Continued)

Cash

The Company continually monitors its positions with, and the credit quality of, the financial institutions with which it invests. As of and during the years ended December 31, 2025 and 2024, cash balances were primarily held by one financial institution.

Commodity Derivative Instruments

SJM II and its subsidiaries use commodity derivative instruments to provide a measure of stability to their cash flows in an environment of volatile oil and gas prices and to manage their exposure to oil and gas price volatility. All commodity derivative instruments are initially, and subsequently, measured at estimated fair value and recorded as assets or liabilities on the combined balance sheet.

SJM II is the named counterparty to the commodity derivative contracts pertaining to the Company's natural gas production and natural gas volumes. As these commodity derivative instruments relate to the Company's natural gas volumes, the fair values, and the related realized and unrealized gains/losses attributable thereto, have been pushed down to these combined financial statements for each of the years presented.

SJM II allocates realized and unrealized gains and losses associated with commodity derivative instruments to the Company based on TRR II and CMP's proportionate share of the total monthly production volumes for SJM II.

SJM II and the Company have elected not to designate commodity derivative instruments as cash flow hedges. For commodity derivative instruments that do not qualify as cash flow hedges, changes in the estimated fair value of the contracts are recorded as gains and losses in the combined statement of operations. When commodity derivative instruments are settled, SJM II and the Company recognize realized gains and losses in the combined statement of operations. Derivative cash flows are reported as cash flows from operating activities in the combined statement of cash flows (see Note 4).

Revenue Recognition

The Company's revenue is primarily derived from the sale of its produced oil and natural gas from wells in which the Company has nonoperated royalty interests.

The Company's produced oil and natural gas is produced and sold in the Pennsylvania, West Virginia, and Louisiana geographic areas. Oil sales for the years ended December 31, 2025 and 2024 were $550,506 and $798,814, respectively. Natural gas sales for the years ended December 31, 2025 and 2024 were $26,676,312 and $15,911,728, respectively. Natural gas liquids sales for the years ended December 31, 2025 and 2024 were $5,793,924 and $5,604,655, respectively. Accounts receivable from royalty revenue were $3,808,741 as of January 1, 2024.

The sales of produced oil and natural gas are made under contracts that the operators of the wells have negotiated with customers, which typically include variable consideration based on monthly pricing tied to local indices and volumes delivered. While revenue is typically recorded at the point in time when control of the produced oil and natural gas transfers to the customer, statements and payment may not be received via the operator of the wells for one to three months after the date the produced oil and natural gas are delivered, and, as a result, the amount of production delivered to the customer and the price that will be received for the sale of the product are estimated utilizing production reports, market indices, and estimated differentials. Estimated revenue due to the Company is recorded within accounts receivable in the accompanying combined balance sheet until payment is received. Differences between the estimated amounts and the actual amounts received from the sale of the produced oil and natural gas are recorded when known, which is generally when statements and payment are received.

The Company utilizes the practical expedient in ASC 606, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. As the Company has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to the remaining performance obligations is not required.

The Company also derives revenue from mineral lease bonuses. The Company generates lease bonus revenue by leasing its mineral interests to exploration and production companies. The lease agreements generally transfer the rights to any oil or natural gas discovered, grant the Company a right to a specified royalty interest, and require that drilling and completion operations commence within a specified time period, or the lease will expire. The Company recognizes such lease bonus revenue once the lease agreement has been executed, payment is received, and the Company has no further obligation to refund the payment.

Note 2 - Significant Accounting Policies (Continued)

Given that the Company does not recognize lease bonus income until a lease agreement has been executed, at which point its performance obligation has been satisfied, and payment is received, the Company does not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period.

Unit-based Compensation

The Company follows authoritative guidance that applies to unit-based awards, which requires entities to recognize compensation expense for awards issued to employees and others. Authoritative guidance also requires unit-based awards to employees and others by a related party or other holder of an economic interest in the entity to be accounted for as unit-based transactions if awards are for services provided by such employees and others (see Note 8).

Concentrations of Credit Risk

The Company's producing properties are all located in Pennsylvania, West Virginia, and Louisiana, and the oil, natural gas, and natural gas liquids production is sold by various operators based on market index prices. For the years ended December 31, 2025 and 2024, three operators accounted for 76 and 81 percent, respectively, of revenue. As of December 31, 2025 and 2024, three operators accounted for 77 and 87 percent, respectively, of oil and gas revenue receivables. The risk of nonpayment by these purchasers is considered minimal, and the Company does not generally obtain collateral for sales. The Company continually monitors the credit standing of the primary purchasers and assesses the recoverability of the receivables to determine their collectibility. As the receivables are primarily with other entities within the oil and gas industry, such concentration may impact the Company's credit risk, as these entities may be similarly impacted by economic or other changes within the oil and gas industry.

The Company accrues a reserve for the allowance for credit losses based on management's current estimate of expected credit losses that includes historical credit loss experience of financial assets with similar risk characteristics, adjusted for management's current expectation of current conditions and reasonable and supportable forecasts. The risk of nonpayment is considered minimal; therefore, an allowance for doubtful accounts has not been recorded as of December 31, 2025 and 2024.

Oil and Gas Properties

The Company uses the successful efforts method of accounting for its oil and gas producing activities. Under this method of accounting, costs associated with the acquisition, drilling, and equipping of successful exploratory wells and costs of successful and unsuccessful development wells are capitalized and depleted, net of estimated salvage value, using the units of production on a field-by-field basis based upon proved oil and gas reserves. The Company’s proved oil and gas reserve information was computed by applying the average first day of the month oil and gas price during the 12-month periods ended December 31, 2025 and 2024. Depletion expense associated with proved oil and gas properties for the years ended December 31, 2025 and 2024 was approximately $7,219,000 and $7,377,000, respectively. Exploration, geological costs, delay rentals, and drilling costs of unsuccessful exploratory wells are charged to expense as incurred.

Costs associated with unevaluated exploratory wells are excluded from the depletable basis until the determination of proved reserves, at which time those costs are reclassified to proved oil and gas properties and subject to depletion. If it is determined that the exploratory well costs were not successful in establishing proved reserves, such costs are expensed at the time of such determination.

The Company reviews its oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. The Company estimates the expected future cash flows of its proved oil and gas properties and compares such cash flows to the carrying amount of the proved oil and gas properties to determine if the amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust its proved oil and gas properties to estimated fair value. The factors used to estimate fair value include estimates of proved reserves, future commodity prices adjusted for basis differentials, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the projected cash flows. The discount rate is a rate that management believes is representative of current market conditions and includes estimates for a risk premium and other operational risks. There were no proved oil and gas property impairments during the years ended December 31, 2025 and 2024.

Unproved oil and gas properties are assessed at least annually to determine whether they have been impaired by the drilling of dry holes on or near the related acreage or other circumstances that may indicate a decline in value. When unproved property is determined to be impaired, a loss equal to the portion impaired is recognized. If and when leases for unproved properties expire, the costs thereof are removed from the accounts and charged to expense. There were no unproved property impairments during the years ended December 31, 2025 and 2024.

Note 2 - Significant Accounting Policies (Continued)

Upon the drilling of successful wells on unproved properties, the Company reclassifies cost basis from unproved to proved properties, at which time that cost basis is subject to depletion.

From time to time, the Company may sell its oil and gas properties. The partial sale of proved properties within an existing field is accounted for as a normal retirement, and no gain or loss on divestiture is recognized as long as this treatment does not significantly affect the units-of-production depletion rate. The partial sale of unproved property is accounted for as a recovery of cost when substantial uncertainty exists as to the ultimate recovery of the cost applicable to the interest retained. A gain on divestiture activity is recognized to the extent that the sale price exceeds the carrying amount of the unproved property. A gain or loss is recognized for all other sales of proved and unproved properties. The Company had no material sales of oil and gas properties during the year ended December 31, 2025. The Company had material sales of proved and unproved oil and gas properties during the year ended December 31, 2024 (see Note 6).

Income Taxes

TRR II and CMP are limited liability companies that are disregarded entities for U.S. federal income tax purposes. Accordingly, their taxable income or loss is included in the federal income tax return of SJM II, which is treated as a partnership for U.S. federal income tax purposes. As a partnership, SJM II is not subject to U.S. federal income taxes; rather, its taxable income or loss is allocated to its members, who are responsible for the related income taxes.

Beginning on January 1, 2018, new rules apply to Internal Revenue Service (IRS) audits of partnerships. Under these rules, adjustments resulting from an IRS audit may be assessed at the partnership level on behalf of the members. As of December 31, 2025, the Company has no tax years under audit.

Note 3 - Fair Value Measurements

Accounting standards require certain assets and liabilities be reported at fair value in the financial statements and provide a framework for establishing that fair value. The framework for determining fair value is based on a hierarchy that prioritizes the inputs and valuation techniques used to measure fair value.

Fair values determined by Level 1 inputs use quoted prices in active markets for identical assets or liabilities that the Company has the ability to access.

Fair values determined by Level 2 inputs use other inputs that are observable, either directly or indirectly. These Level 2 inputs include quoted prices for similar assets and liabilities in active markets and other inputs, such as interest rates and yield curves, that are observable at commonly quoted intervals.

Level 3 inputs are unobservable inputs, including inputs that are available in situations where there is little, if any, market activity for the related asset or liability. These Level 3 fair value measurements are based primarily on management’s own estimates using pricing models, discounted cash flow methodologies, or similar techniques taking into account the characteristics of the asset or liability.

In instances where inputs used to measure fair value fall into different levels in the above fair value hierarchy, fair value measurements in their entirety are categorized based on the lowest level input that is significant to the valuation. The Company’s assessment of the significance of particular inputs to these fair value measurements requires judgment and considers factors specific to each asset or liability.

Note 3 - Fair Value Measurements (Continued)

The following tables present information about the Company’s assets and liabilities measured at fair value on a recurring basis at December 31, 2025 and 2024 and the valuation techniques used by the Company to determine those fair values:

The Company's derivative instruments consist of commodity swaps. The Company estimates the fair values of its commodity swaps under the income valuation technique using a discounted cash flow model. The valuation models require a variety of inputs, including contractual terms, published forward prices, and discount rates, as appropriate. The Company's estimates of the fair value of commodity derivative instruments include consideration of the counterparty's creditworthiness, the Company's creditworthiness, and the time value of money. The consideration of these factors results in an estimated exit price for each derivative asset or liability under a marketplace participant's view. The Company believes that the valuation methods utilized are appropriate and consistent with the fair value standards and with other market participants. All of the significant inputs are observable, either directly or indirectly; therefore, the Company's commodity swap instruments are included within the Level 2 fair value hierarchy.

The financial and nonfinancial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company's policy is to recognize transfers in and/or out of the fair value hierarchy as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.

The Company's financial instruments consist of accounts receivable. The carrying value of accounts receivable approximates fair value due to the short-term nature of these instruments.

Note 4 - Derivatives

As discussed in Note 2, SJM II periodically enters into various commodity derivative instruments to mitigate a portion of the effect of natural gas price fluctuations. SJM II and its subsidiaries classify the fair value amounts of derivative assets and liabilities as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty.

Note 4 - Derivatives (Continued)

At December 31, 2025 and 2024, the fair values attributable to certain commodity derivative instruments in which SJM II was the named counterparty of the derivative agreements have been allocated to the Company based on TRR II's and CMP's proportionate share of SJM II's total estimated monthly production over the duration of the derivative contracts. The fair values as of December 31, 2025 are as follows:

The fair values as of December 31, 2024 are as follows:

As of December 31, 2025, the Company had $496,781 of gross current commodity derivative assets offset by $135,459 of current liabilities, resulting in a net current commodity derivative asset of $361,322. The Company had $161,428 of gross noncurrent commodity derivative assets offset by $70,991 of noncurrent liabilities, resulting in a net noncurrent commodity derivative asset of $90,437.

As of December 31, 2024, the Company had $2,133,378 of gross current commodity instrument assets offset by $526,787 of current liabilities, resulting in a net current commodity derivative asset of $1,606,591. The Company had $464,153 of gross noncurrent commodity derivative liabilities, with no assets offsetting the balance.

Due to the volatility of natural gas prices, the estimated fair values of the Company's allocated commodity derivative instruments are subject to large fluctuations from period to period.

The counterparty to the SJM II derivative instruments is East West Bank. The Company and SJM II are not required to post collateral with East West Bank since the Credit Agreement (see Note 5) is collateralized by SJM II's and the Company's oil and gas assets.

Note 4 - Derivatives (Continued)

For the years ended December 31, 2025 and 2024, the gains and losses recognized in the combined statement of operations attributable to derivative instruments are as follows:

Note 5 - Member Debt Guarantee

In July 2018, SJM II entered into a credit agreement with East West Bank (the "Credit Agreement") with a maximum commitment of $75,000,000. The borrowing base is redetermined semiannually, with the borrowing base as of December 31, 2025 set at $100,000,000 and a maximum commitment of $200,000,000. Repayment of borrowings is required in the event that the redetermined borrowing base is less than outstanding borrowings or on the maturity date. During 2024, the maturity date was extended to July 2027. In May 2026, the Credit Agreement was amended to extend the maturity date to July 2029. Amounts borrowed bear interest at SOFR or the base rate, as defined, plus a margin ranging from 3.00 to 4.00 percent depending on utilization (7.415 percent at December 31, 2025). Interest is payable monthly.

The Credit Agreement contains financial covenants requiring minimum current, maximum leverage, and minimum interest coverage ratios. As of December 31, 2025, SJM II was in compliance with these financial covenants. The Credit Agreement contains restrictive covenants, including the limitation of paying distributions to the members of SJM II, the transfer of more than 40 percent of the equity interests in SJM II, and incurring additional indebtedness. The Credit Agreement is collateralized by all mineral interests of SJM II and its subsidiaries, including TRR II and CMP. As of December 31, 2025, the outstanding amount borrowed by SJM II under the Credit Agreement was $70,800,000. SJM II is required to enter into and maintain hedge transactions of crude oil and natural gas covering 50 to 90 percent of SJM II's anticipated oil and natural gas production, or anticipated receipt of royalties, from its proved developed producing properties.

In addition, each of the Guarantors (see Note 1) guarantees the amounts owed under the Credit Agreement by SJM II. The Guarantors are not joint and severally liable under the Credit Agreement, and SJM II is the only named borrower under the Credit Agreement. As it is not probable that TRR II and/or CMP will be forced to act upon their guarantees, no amounts outstanding under the Credit Agreement, along with any associated interest costs, have been allocated to the combined carve-out financial statements of the Company.

In addition, as of December 31, 2025 and 2024, SJM II had two interest rate swap derivative instruments, each with $10,000,000 of notional and a maturity date of July 2026 (the "Swaps"). Each of the Swaps had SJM II as the fixed rate payer at 4.45 percent and 3.83 percent, respectively, on the one-month SOFR. As SJM II is the only named counterparty on the Swaps and no amounts outstanding under the Credit Agreement at the SJM II level have been allocated to either TRR II or CMP as discussed above, no amounts related to the Swaps have been pushed down to these combined carve-out financial statements.

Note 6 - Oil and Gas Property Sales

In September 2024, TRR II sold approximately 20 percent of its mineral rights in its Appalachian oil and gas properties to an unrelated third party for net proceeds of approximately $29,168,000. The transaction closed on September 17, 2024. As part of the sale, TRR II sold $11,431,142 of unproved property, which was accounted for as a recovery of basis, and no gain was recognized. Additionally, TRR II sold $7,038,950 of net proved properties, which resulted in a net gain of $10,698,124. The results of the sold oil and gas properties have not been disclosed separately from continued operations within these financial statements because the sale did not represent a strategic shift in operations for TRR II.

Note 7 - Litigation

The Company is occasionally named a party in lawsuits in the normal course of business. In the opinion of management, the resolution of these lawsuits will not have a material adverse effect on the Company's financial position or results of operations.

Note 8 - Member's Equity

TRR II was formed in 2017, pursuant to a limited liability company agreement, as amended (the "TRR II Agreement"). The TRR II Agreement provides for the authorization of one class of common interests, in which SJM II is the sole member.

CMP was formed in 2017, pursuant to a limited liability company agreement, as amended (the "CMP Agreement"). The CMP Agreement provides for the authorization of one class of common interests, in which SJM II is the sole member.

Certain employees of SJM II (see Note 9) who provide management and administrative services to the Company were granted management incentive units of SJM II (the "MIUs"). The MIUs entitle the holders to the right to receive distributions from SJM II upon the attainment of specific payout thresholds. MIUs vest upon service conditions or performance conditions related to monetization events. During 2025 and 2024, there were no grants of MIUs. As of December 31, 2025 and 2024, approximately 99 percent of authorized MIUs were issued and outstanding, of which approximately 83 percent and 79 percent were contractually vested as of December 31, 2025 and 2024, respectively. For the years ended December 31, 2025 and 2024, the Company's allocable share (based on the proportion of revenue and capital expenditures; see Note 1) of grant-date fair value recognized as compensation expenses as a component of general and administrative expenses - related party within the combined statement of operations totaled approximately $260,000 and $219,000, respectively. The proportion of unrecognized compensation cost estimated to be allocable to the Company as of December 31, 2025 was approximately $272,000.

Note 9 - Related Party Transactions

As discussed in Note 1, during 2017, SJM II entered into the MSA with SJM I, an entity with common ownership and common management, whereby shared management services and general overhead of the SJM Entities are allocated based on time incurred. SJM III and SJM IV subsequently became parties to the MSA. The MSA is subject to automatic annual renewals.

For the years ended December 31, 2025 and 2024, the Company incurred services and shared general overhead, including unit-based compensation, from SJM II of approximately $750,655 and $855,215, respectively, all of which has been included in general and administrative expenses - related party on the accompanying combined statement of operations of the Company.

The Company had miscellaneous general and administrative amounts due (to) from SJM III totaling $(1,165) and $940 as of December 31, 2025 and 2024, respectively, which are included within related party receivables on the accompanying combined balance sheet.

The Company had miscellaneous general and administrative amounts due from SJM I totaling $46,526 and $103,311 as of December 31, 2025 and 2024, respectively, which is included within related party receivables on the accompanying combined balance sheet.

During 2017, SJM I and SJM II entered into an agreement whereby SJM I and the Company's prospective mineral acquisitions shall be restricted to (1) certain counties within Pennsylvania or within two miles of existing company mineral interests and (2) amounts less than $2.0 million. Furthermore, SJM I and the Company may offer SJM II the right to participate in mineral interest acquisitions.

Note 10 - Subsequent Events

In June 2026, SJM II entered into a new interest rate swap agreement, with an effective date of July 2026, with $20,000,000 of notional and a maturity date of July 2028. Under this agreement, SJM II is the fixed rate payer at 3.99 percent and receives the one-month SOFR.

In August 2026, TRR II and CMP entered into a purchase and sale agreement to sell certain oil and gas properties of TRR II and all of the oil and gas properties of CMP for a purchase price of $105,000,000 (the "Transaction"). As of the date these financial statements were available to be issued, the Transaction had not closed. There can be no assurance that the Transaction will eventually close.

The Company has evaluated all subsequent events up through and including September 11, 2026, which is the date these financial statements were available to be issued.

Supplemental Information (Unaudited)

Supplemental Oil and Gas Information (Unaudited)

Oil and Natural Gas Reserve Quantities

The estimates of proved oil and natural gas reserves and discounted future net cash flows for the Company's oil and gas properties as of December 31, 2025 and 2024 were prepared using historical data and other information by qualified petroleum engineers engaged by the Company. Users of this information should be aware that the process of estimating quantities of proved oil and natural gas reserves is complex, requiring significant subjective decisions to be made in the evaluation of geologic, engineering, and economic data for each reservoir. The data for any given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, production history, and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time.

The estimated proved net recoverable reserves presented below include only those quantities of oil and natural gas that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic, operating, and regulatory practices. In accordance with the SEC's guidelines, estimates of proved reserves from which present values are derived were based on the unweighted 12-month average price of the first day of the month price for the period and held constant. Proved developed reserves represent only those reserves estimated to be recovered through existing wells. When and if the Company has insight into the development plans for each of the operators in which the Company holds royalty interests, the Company will recognize proved undeveloped reserves. All of the oil and gas reserves set forth herein are in the United States and are proved reserves.

The estimated rounded quantities of proved developed oil and natural gas reserves and changes in net proved reserves are summarized below for the year ended December 31, 2025: